To maintain and repair wells, risers and pipelines in land-based and subsea petroleum well production systems (tubing systems), it is important to have access from one end of the pipe/tube/riser/conduit/well/gathering line for pigging, fishing or coiled tubing operations. Unrefined petroleum products flowing inside metal pipes are known to build up deposits of scale, paraffin and asphaltine compounds on the walls of the pipes. Pigging operations to clean the pipes are performed as often as monthly and more, requiring production to be interrupted for about 2 days.
Multi-phase fluid flowing through tubing systems is a common occurrence in petroleum production systems given that oil wells are usually co-produced with gas, and that gas wells are usually co-produced with water. Such multi-phase fluid from the well is transported through the tubing system to the production point, where the fluid is processed (separated into gas, oil and water). Such production point for subsea petroleum wells is typically the surface platform. Land-based multi-phase tubing systems typically consist of gathering lines to concentrate produced fluid at one large processing facility.
As production of an oil well progresses and the pressure declines in the reservoir, the proportion of free gas phase present in the pipes increases systemwide as more gas comes out of solution. As the gas phase expands, less efficient gas-liquid mixture flow regimes (more gas phase slippage past liquid) form in the conduits systemwide leading to lower liquid production. In vertical conduits, the flow progresses through the following flow regimes in declining order for liquid production: bubble flow, slug flow, churn flow, annular flow and then misty annular flow. In horizontal or inclined conduits, the flow progresses through the following flow regimes: bubble flow, stratified flow, stratified wavy flow, elongated bubble flow, slug flow, annular flow and then misty annular flow.
Similarly, as gas wells mature, the reservoir pressure declines and increasing quantities of water are produced, which inhibits the flow of the gas phase and accelerates the decline in gas production. Any water produced will be detrimental to the flow of gas, adding to the mass of the production fluid. From the perspective of flow assurance, more problematic is the tendency for the water to collect in the lower region of the well (in the wellbore), pipelines and toward the bottom of risers, reducing the cross sectional area of the gas to travel (choke effect) and commonly leading to the blockage of the flow of gas (see FIG. 1).
When large slugs form, the liquid does not move until the gas pressure behind the blockage builds up high enough to push the liquid out of the low spot as a slug. Large cyclical flow rates initiated by severe slugs can cause major problems for surface equipment like separator vessels and compressors (see FIG. 2).
Slugging in the riser occurs when the system pressure-loss becomes dominated by hydrostatic head losses, rather than by friction. This is usually the case for a non-choked pipeline-riser. In order to establish a stable, friction-dominated system, a choke near the top of the riser can provide a pressure drop comparable to the hydrostatic head loss over the riser when full of liquid. While this common technique moderates the intensity of slugging behavior, it wastes the potential energy of the reservoir due to the increase in backpressure induced by the high choke pressure.
A number of methods have been employed to control or mitigate slug formation. Active control of subsea chokes can stabilize the wellhead pressure with frequent choke adjustments, but these add complexity to the system and moderate not control slugging behavior. Riser base gas injection (so-called “gaslift”) is a common technique to avoid slugging by continually injecting gas into the riser, preventing the build-up of liquid and resultant blockage to gas flow. Riser base gaslift mitigates severe slugging, reducing the mass of the slug and so the magnitude of its impact. While gaslift mitigates severe slugging behavior, it also adds to capital costs, operating complexity and ongoing expense of gas and compression.
The invention is not to be confused with so-called “dual bore completions” or a “dual riser” in subsea systems, such applications relate to improving access during drilling, service or repair operations, not for providing an alternate production fluid path or for altering flow dynamics of the fluid flowing through the production pipe/riser as disclosed by the present invention. In U.S. Pat. No. 6,443,240, Robert Scott describes a novel method and apparatus for offshore drilling operations, more specifically, relating to a dual riser method and apparatus for use in drilling and/or production work over a single well hole in deep water applications, enabling a deep water drilling rig to have dual turntables to work simultaneously through two parallel risers to shorten the critical path associated with deep water drilling and/or workover activity.
There is a substantial need therefore to improve/manage the gas-oil-ratio of producing oil wells to improve reservoir depletion characteristics, to continuously evacuate liquid accumulating in the wellbore of gas and condensate wells to increase gas production rates, to control liquid slugging in risers and in pipelines with hilly terrain and to protect surface production facilities and pipelines from irregular fluid production, while at the same time permit access for pigging, fishing and coiled tubing operations.
The present invention comprises a combination of features and advantages that enable it to overcome various problems with the prior methods. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description of the preferred embodiments of the invention, and by referring to the accompanying drawings. Any design feature or method described in any one embodiment of the invention may also be assumed for potential application in any of the other embodiments described herein.